Bureau of Air Curtis State Office Building 1000 SVI! Jackson. Suite 310 Topeka, KS 66612**Rob~n** Moser, lv1D, Secretary

Source ID No. 0210002

Mr. Jeff Burkett Senior Environmental Coordinator The Empire District Electric Company P.O. Box 127 Joplin, Missouri 64802 Department ofllealth & Environment July 11,2013

RE: Air Emission Source PSD Construction Permit- Riverton Power Station

Dear Mr. Burkett: Phone: 785-296-6281 Fax: 785-291-3953 llowry@kdheks.gov www. kd heks. gov/bar

Sam BroWI1hl-lck, Cfovcrnor

Enclosed is the Air Emission Source PSD Construction Permit for the conversion of Unit 12 from simple cycle to combined cycle operation at The Empire District Electric Company facility located in Riverton, Kansas. Also enclosed is a copy of the Responsiveness Summary. Please review the enclosed Air Emission Source Construction Permit carefully, since it obligates The Empire District Electric Company to certain requirements. The source ID number listed above should be included in all communications with the Kansas Department of Health and Environment (KDHE) in reference to this approval.

As provided for in K.S.A. 65-3008b(e), an owner or operator may request a hearing within 15 days after affirmation, modification or reversal of a permit decision pursuant to subsection (b) ofK.S.A. 65-3008a. In the Request for Hearing, the owner or operator shall specify the provision of this act or rule and regulation allegedly violated, the facts constituting the alleged violation and secretary's intended action. Such request must be submitted to: Director, Office of Administrative Hearings, 1020 S. Kansas Avenue, Topeka, Kansas 66612- 1327. Failure to submit a timely request shall result in a waiver of the right to hearing.

If you have any questions about the enclosed amendment to the construction permit, or need any additional information, please contact me at (785) 296-6281.

LDL:lv Enclosures
c: Doug Cole, SEDO C-10913 Sincerely,

# ~.owr;,~ En 1ronmental Engineer Air Permitting SectionBureau of Air Curtis State Office Building 1000 SW Jackson, Suite 310 Topeka, KS 66612-1366

Robert Moser, MD, Secretary



### Source ID No.:
Effective Date: Depm1ment of llealth & Environment



### AIR EMISSION SOURCE CONSTRUCTION PERMIT

0210002 July 11, 2013 Phone: 785-296-6281 Fax: 785-291-3953 llowry@kdheks.gov www.kdheks.gov/bar

Sam Brownback, Governor



### Source Name: The Empire District Electric Co. -Riverton Generating Station

SIC Code:
NAICS Code:

Source Location:

Mailing Address:

Contact Person 4911, Electric Services
221112, Fossil fuel power generation

7240 Southeast Highway 66 Riverton, Kansas 66770

P.O. Box 127 Joplin, Missouri 64802

Mr. Jeff Burkett Sr. Environmental Coordinator Telephone Number (417) 625-4236

This permit is issued pursuant to K.S.A. 65-3008 as amended.

I. 

### Description of Activity Subject to Air Pollution Control Regulations
The Empire District Electric Company (Empire), Riverton Unit 12, a Siemens V84.3A(2) natural gasfired combustion turbine, nominally rated at 150 MW, was originally issued a construction permit on October 18,2005 (amended on August 18,2006 and February 5, 2009) and began operation in 2007. Empire plans to convert the existing Riverton Unit 12 simple cycle combustion turbine to a combined cycle unit, with a nominal capacity of 250 MW (1963 MMBtu/hr). The proposed combined cycle unit will replace the capacity and energy provided by coal fired boilers Unit 7 ( 426 MMBtu/hr) and Unit 8 (600 MMBtu/hr), which will both be retired in conjunction with the completion of this project. Empire plans to complete this conversion by June, 2016.
Page 1 of 16Modifications will include a heat recovery steam generator (HRSG) with supplemental natural gas duct firing (duct burners) and a condensing steam turbine generator. A selective catalytic reduction (SCR) system will control oxides of nitrogen (NOx). A carbon monoxide catalyst will control carbon monoxide (CO) and volatile organic compound (VOC) emissions from the turbine and HRSG. Other equipment will include a cooling tower, an 18.6 MMBtu/hr natural gas-fired auxiliary boiler with the capacity to produce 15,000 pounds of steam per hour (approximately 18.6 MMBtulhr), a 1102 HP (750 Kw) emergency diesel engine and two (2) sulfuric hexafluoride (SF 6 ) insulated circuit breakers. Except in the case of an actual emergency, Empire will not operate the emergency diesel engine more than 100 hours per year in a non-emergency capacity to accommodate maintenance and readiness testing.

Emissions increases of NOx, sulfur dioxide (S0 2 ), carbon monoxide (CO), volatile organic compounds (VOC), particulate matter (PM), PM with a diameter less than 10 microns (PM 10 ), PM with a diameter less than 2.5 microns (PM 25 ), lead, sulfuric acid mist (SAM), hydrogen fluoride (HF), and carbon dioxide equivalent (C0 2 e) were evaluated for this review. This is a major modification of a major stationary source for at least one regulated pollutant emitted in excess of the PSD significant emission levels. Since there is an increase in PM, PM 10 , PM 2
. 5 , and C0 2 e emissions in excess of the significant thresholds, the proposed modification will be subject to the requirements of 40 CFR 52.21, Prevention of Significant Deterioration (PSD) as adopted under K.A.R. 28-19-350.

This project is subject to K.A.R. 28-19-300 (Construction permits and approvals; applicability) because the increase in potential- to-emit of PM exceeds 25 tons per year and PM 1 

### o exceeds 15 tons per year. The combined cycle unit (CT+HRSG) is an affected source subject to Title IV of the Federal Clean Air Act, Acid Deposition Control. The emergency diesel engine is subject to the requirements of 40 CFR 60, Subpart IIII, Standards of Performance for Stationary Compression Ignition (CI) Internal Combustion Engines.
An air dispersion modeling impact analysis, an additional impact analysis, and a Best Available Control Technology (BACT) determination were conducted as a part of the construction permit application process.



### II. Significant Applicable Air Pollution Control Regulations

The following significant Kansas air quality regulations were determined to be applicable to this source:

A. K.A.R. 28-19-11, Exceptions due to breakdown or scheduled maintenance

- as applied to state regulations K.A.R. 28-19-30 through 32 and K.A.R. 28-19-650.

B. K.A.R. 28-19-30 through 32, Indirect heating equipment emissions.

C. K.A.R. 28-19-275, Special provisions; acid rain deposition.

D. K.A.R. 28-19-300, Construction permits and approvals; applicability.

E. K.A.R. 28-19-350, which adopts by reference 40 CFR 52.21, Prevention of significant deterioration of air quality.
Page 2 of 16F. K.A.R. 28-19-650, Emissions opacity limits.

G. K.A.R. 28-19-720, which adopts by reference 40 CFR Part 60, New Source Performance Standards.

H. K.A.R. 28-19-750, which adopts by reference 40 CFR Part 63, National Emission Standards for Hazardous Air Pollutants.
I. 40 CFR Part 60, Subpart A, General Provisions.

J. 40 CFR Part 60, Subpart IIII, Standards of Performance for Stationary Compression Ignition Internal Combustion Engines.

K. 40 CFR Part 63, Subpart A, General Provisions.

L. 40 CFR Part 63, Subpart ZZZZ, National Emissions Standards for Hazardous Air Pollutants for Stationary Reciprocating Internal Combustion Engines.

M. 40 CFR Part 63 Subpart YYYY, National Emission Standards for Hazardous Air Pollutants from Stationary Combustion Turbines. Subpart YYYY, 63.6145 requires initial notification. Owners
or operator of lean premix gas-fired stationary combustion turbines or diffusion flame gas-fired turbines must comply with the initial notification requirements set forth in 40 CFR 63.6145 but need not comply with any other requirement of 40 CFR Part 63 Subpart YYYY until EPA takes final action to require compliance and publishes a document in the Federal Register. [40 CFR 63.6095(d)] As of the date on this application, the EPA has not published such a document in the Federal Register.

N. 40 CFR Part 60 Subpart KKKK, Standards of Performance for Stationary Gas Turbines, applies to stationary combustion turbines with a heat input at peak load equal to or greater than 10 MMBtu/hr, based on the higher heating value of the fuel, which commenced construction, modification, or reconstruction after February 18, 2005.

0. 40 CFR Part 60 Subpart De, Standards of Performance for Small Industrial CommercialInstitutional Steam Generating Units applies to the auxiliary boiler. Since the auxiliary boiler will fire solely natural gas it is subject to the Reporting and Recordkeeping requirements of 40 CFR Part 60, Subpart De [40 CFR 60.48(c)].
P. 40 CFR Part 63 Subpart 40 CFR Part 63 Subpart DDDDD Industrial, Commercial, and Institutional Boilers and Process Heaters (Boiler MACT) apply to the auxiliary boiler. Since the auxiliary boiler will fire solely natural gas it will not be subject to any emissions limits, but rather will be subject to a work practice standard that requires an annual tune-up in lieu of emission limits.

Page 3 of 16Q. 

### 40 CFR Part 72 through Part 78, Acid Rain Program (ARP), applies to utility units. A utility unit is defined as a unit owned or operated by a utility that serves a generator in any state that produces electricity for sale. Unit 12, when converted to a combined cycle operation, will continue to be subject to the ARP. The ARP requires various pollutant monitors in addition to possession of S02 allowances for each ton of S02 emitted. The current ARP permit, under which unit 12 currently operates will be modified as the project is completed.

III. Air Emission Unit Technical Specifications


### The following equipment or equivalent is approved.

A. Combined cycle combustion unit (CT+HRSG)- Conversion of one (I) Siemens Westinghouse Model V84.3A(2) simple cycle combustion turbine/generator, known as emission Unit 12, equipped with dry low NOx burners, to a combined cycle operation, burning natural gas. The manufacturer's estimated performance is 250 MW. The combined cycle unit includes a heat recovery steam generator (HRSG) with supplemental natural gas duct firing (duct burners) and a condensing steam turbine generator with SCR and CO catalyst

B. One mechanical draft cooling tower with high efficiency drift eliminator to reduce aerosol and particulate emissions from the tower.

C. 

### One 750 Kw emergency diesel engine.

D. One 18.6 Mm Btu/hr natural gas-fired auxiliary boiler with the capacity to produce 15,000 pounds of steam per hour. The auxiliary boiler is designed to operate when the combined cycle unit is in a brief period of shutdown and for startup.
E. Two (2) Sulfur Hexafluoride (SF 6 )- 

### insulated circuit breakers.

IV. Air Emissions Estimates from the Proposed Activity


### The air emissions estimates are shown below:

Baseline Actual Emissions and Projected Actual Emissions (tons per year) Units 7 Total Projected Actual Unit 12 I· 

### Baseline Unit 12 &8 Baseline Actual Emissions PSD 

### Pollutant Baseline Actual (Unit 12 Actual Units 7, 8 Increase Significance 

### Type Actual (before & Unit 12 After Combined Cycle Threshold 

### Project) (before Project) Project minus Project) Total Baseline)

NOx 1120 34 1154 67 -1087 

### 40
Page 4 of 16

## so2 5004 1 5005 12 -4993 

### 40



## co 90 3 93 60 -33 

### 100



## voc 10 0.3 10.3 47.3 37 

### 40

Lead 0.5



### -- 0.5 4.lx10- 5 

### -0.5 

### 0.6

SAM 2 0.1 2.1 6.93 4.83 7



### HF 25



### -- 25 1.69x10· 5 

### -25 3



### PM 91 7 

### 98 132 34 

### 25

PM to 

### 66 7 

### 73 132 59 

### 15

PM2.s 26 7 33 132 99 

### 10

C0 2 

### e 640,234 123,604 763,838 1,020,590 256,752 

### 75,000

V. Air Emission Limitations
A. The BACT emission limitations established in this permit apply to the combined cycle unit (CT+HRSG) at all times, including startup, shutdown and malfunction, except as provided in Section VII. Performance Testing and Compliance, H. Malfunction, of this permit.

B. K.A.R. 28-19-650 (a)(3): Opacity of visible emissions from all emission units shall not exceed 20 percent.
C. Particulate matter emissions from all indirect heating equipment are limited to the amount determined by the following equation [K.A.R. 28-19-3l(a)]:

A = 1. 

### 026 II 0233



### Where: A= the allowable emission rate in lb 

### I I 0 6 

### Btn I =the total heat input of all boilers in 10 6 

### Btu

D. The NO, emissions from the combined cycle unit (CT+HRSG) shall meet the applicable emission limits specified in 40 CFR 60.4320(a). NO, emission limits shall not exceed the limits specified in Table 1 to Subpart KKKK of Part 60-Nitrogen Oxide Emission Limits for New Stationary Combustion Turbines. The NO, emission limit specified in 40 CFR 60.4350(h) is 15 ppm@ 15% 0 2 

### on a 30 unit operating day rolling average.
E. 

### The S0 2 

### emissions from the combined cycle unit (CT +HRSG) shall meet the applicable emission limits specified in 40 CFR 60.4330(a) which is 110 Nanogram/joule (0.90 lb/gross MW-hr).

Page 5 of 16F. The BACT PM/PM 10 /PM 2 

### .s emissions shall not exceed:

1. 30.2 lb per hour (front+ back half) for the combined cycle unit (CT + HRSG).

2. 0.005 lb/MMBtu for the auxiliary boiler.

3. 0.15 g/bhp-hr for the diesel engine

4. drift rate of0.0005 percent of inlet flow for the mechanical draft cooling tower

G. The BACT Greenhouse Gas emissions shall not exceed:

1. For the combined cycle combustion turbine and duct burners.

a. C0 2 emissions are limited to 1,021,770 tons C0 2 /year on a 12-month rolling basis,

and the following equation (Equation G-4 of Section 2.3 of 40 CFR Part 75, Appendix G, Revised March 19, 2012):

(Eq. 

### G-4)

Where:

W c 02**~** C0 2 emitted from combustion, tons/hr.
MW C0 2**~Molecular** weight of carbon dioxide, 44.0 lbllb-mole. F,**~Carbon** based F-factor, 1040 scf/mmBtu for natural gas; 1,420 scf/mmBtu for crude, residual, or distillate oil; and calculated according to the procedures in section 3.3 .5 of appendix F of 40 CFR, Part 75 for other gaseous fuels.
H**~Hourly** heat iuput in MMBtu, as calculated using the procedures in Section 5 of Appendix F of 40 CFR, Part 75.**u,~** 1/385 scf C0 2 /lb-mole at 14.7 psia and 68 °F.

b. BACT emission limits are required for C0 2 , only, since it is 99.9% of emissions.

2. For the Auxiliary boiler.

a. C0 2 emissions are limited to 9,512 tons C0 2 /year on a 12-month rolling basis and the following equation:

C0 2 (lb/MMBtu)**~** Efx (2.20462lb/kg)

Page 6 of 16

### Where:
Ef =Emission Factor for C0 2 

### in kg C0 2 

### /MMBtu using specified values for natural gas fuel from Table C-1 of 40 CFR Part 98, Subpart C, Revised May 31, 2013)
b. BACT emission limits are required for C0 2 , 

### only, since it is 99.9% of emissions.

3. For the Emergency generator.
C0 2 

### emissions are limited to 59.3 tons C0 2 

### /year on a 12-month rolling basis and the following equation:
C0 2 

### (lb/MMBtu) = Efx (2.20462lb/kg)
Where:
Ef =Emission Factor for C0 2 

### in lb/MMBtu using specified values for Distillate Fuel Oil No.2 from Table C-1 of 40 CFR Part 98, Subpart C, Revised May 31, 2013)
b. BACT emission limits are required for C0 2 , 

### only, since it is 99.9% of emissions

4. Sulfur hexafluoride (SF 6 

### l Electrical Breakers.

a. Maintain fugitive emissions below 0.5% (by weight) of SF 6 

### with state-of-the-art SF6 circuit breakers with leak detection and implementation of an LDAR program and density monitor alarm set to 4 psi drop.

H. Pursuant to 40 CFR 60.4205(b ), the owner or operator of the emergency diesel engine, shall comply with the applicable emission standards. In accordance with 40 CFR 60.4205(b ), which references 40CFR 89.112 and 40 CFR 89.113, the emergency diesel engine's NMHC+ NOx emissions shall not exceed 6.4 g!kW-hr (4.8 g/hp-hr), CO emissions shall not exceed 3.5 g/kWhr (2.6 g!hp-hr), and PM emissions shall not exceed 0.2 g/kW-hr (0.15 g/hp-hr) over the life of the engine. The emergency diesel engine shall be certified by the manufacturer to meet these emission limits per 40 CFR 60.4202(a)(2). The owner or operator shall also meet the requirements of 40 CFR 60.4206. I. 

### The facility shall comply with applicable requirements of 40 CFR Part 63 Subpart ZZZZ (refer to 40 CFR 63.6590(c)). If a conflict exists between the federal rule and the permit, requirements of the federal rule shall take precedent. J. 

### Applicability of Federal Rule General Provisions. For the emergency diesel engine, 40 CFR 60.4218 identifies the Subpart A requirements that are applicable. Empire shall also comply with Subpart A, as applicable, for Subparts KKKK and De.

Page 7 of 16

### VI. Permit Conditions

A. Startup and shutdown are defined as follows:

1. Startup: The period from when the combined cycle unit (CT +HRSG) is started until reaching 50% of the combustion turbine (CT) load. The startup periods will be readily identifiable by the monitoring system. Such periods shall not exceed 8 hours.

2. Shutdown: The period when the combined cycle unit (CT +HRSG) is shutting down from 50% of combustion turbine (CT) load to 0% of combustion turbine (CT) load. The shutdown periods shall be readily identifiable by the monitoring system. Such periods shall not exceed 2 hours.

B. The combined cycle unit (CT +HRSG) shall operate at load conditions between 50% of combustion turbine (CT) load and 100% of combined cycle unit (including HRSG and maximum duct burner firing capacity except during startup and shutdown.

C. The combined cycle unit (CT +HRSG) shall use only natural gas as a fuel.

D. The high efficiency drift eliminators for the Mechanical Draft Cooling Tower are an integral part of the design and shall function any time the cooling tower is in operation.

E. Compliance with the PM/PM 10 PM 25 BACT limit for the Mechanical Draft Cooling Tower shall be demonstrated by maintaining records of the vendor-guaranteed drift rate of 0.0005 percent of inlet flow. No chromium-based water treatment chemicals shall be used in the circulating water system and thus the requirements of 40 CFR Part 63, Subpart Q shall not apply.

F. The emergency diesel engine shall burn only low sulfur diesel fuel oil that is 

### ::S (less than or equal to) 15 ppm sulfur in accordance with 40 CFR 60.4207(b).

G. Compliance with the PM/PM 10 /PM 2

. 5 and C0 2 e BACT limit for the emergency diesel engine is established by the BACT analysis and emissions calculations submitted with the permit application. H. The auxiliary boiler shall use only natural gas as a fuel.
I. Compliance with the PM/PM 101 PM 2 5 BACT limit for the auxiliary boiler is established by the BACT analysis and emissions calculations submitted with the permit application. J. Compliance with the C0 2 e BACT limit for the combined cycle unit, including the combustion turbine and duct burners shall be demonstrated with an oxygen (0 2 ) concentration monitor in accordance with C0 2 calculations provided in 40 CFR Part 75. Calculations shall consist of C02 emissions only, which account for 99.9% of total C02e emissions.

K. Compliance with the PM/PM 101 PM 25 BACT limit for the combined cycle unit shall be demonstrated with a performance test. Page 8 of 16L. Compliance with the C0 2 e BACT limit for the auxiliary boiler shall be demonstrated by recording fuel usage and using emissions factors from Tables C-1 and C-2 of 40 CFR Part 98, Subpart C along with the Global Warming Potential Factors from Table A-1 of 40 CFR Part 98, Subpart A (as published in 74 FR 56374 on October 30, 2009) to determine resulting emissions
on a monthly basis. Reports of excess emissions shall be submitted semi-annually.

M. The SF 6 Insulated Circuit Breakers shall continuously use a density (leak detection) alarm system on the SF 6 circuit breakers with a threshold of 10 percent. In the event of an alarm, the
owner or operator shall immediately investigate the event and take an necessary corrective action to address any problems.

N. Compliance with the C0 2 e BACT limit for the SF 6 Insulated Circuit Breakers shall be demonstrated by calculating the annual mass emissions of SF 6 from the electrical breakers using
an annual SF 6 leak rate of 0.5% by weight and the Global Warming Potential Factor for SF6 from Table A-1 of 40 CFR Part 98, Subpart A (as published in 74 FR 56374 on October 30, 2009) to determine resulting emissions on a monthly basis. Reports of excess emissions shall be submitted semi-annually.

0. 40 CFR Part 60 Subpart IIII- Requirements for the emergency diesel engine: 1. For the emergency diesel engine, 40 CFR 60.4218 identifies the Subpart A requirements that are applicable. 2. The owner or operator shall comply with applicable diesel fuel requirements of 40 CFR 60.4207(b ). 3. For the emergency diesel engine, the provisions of 40 CFR 60.4211(£) apply. Maintenance checks and readiness testing is limited to 100 hours per year, of which up to 50 hours per year may be for non-emergency situations. There is no time limit on the use of the emergency diesel engine in emergency situations. 4. The owner or operator shall comply with applicable requirements of 40 CFR Part 60 Subpart IIII. If a conflict exists between the federal rule and the permit, the requirements of the federal rule shall take precedence. P. In accordance with 40 CFR Part 63 Subpart 40 CFR Part 63 Subpart DDDDD Industrial, Commercial, and Institutional Boilers and Process Heaters, the auxiliary boiler, firing solely natural gas, is subject to a work practice standard that requires an annual tune-up in lieu of emission limits. 

### Q. Monitoring Requirements for Emergency Diesel Engine

- If the emergency diesel engine does not meet the standards applicable to non-emergency engines, the owner or operator must install a non-resettable hour meter prior to startup of the engine, as specified in 40 CFR 60.4209. R. Empire shall permanently remove Unit 7 and Unit 8 from service when the Unit 12 combined cycle unit (CT +HRSG) begins commercial operation.

Page 9 of 16VII. Performance Testing and Compliance


### A. Within 60 days after achieving a maximum production rate at which the combined cycle unit (CT +HRSG) will be operated, but not later than 180 days after initial start-up of the combined cycle unit, and every 5 years thereafter, the owner or operator shall conduct performance test(s) for PM, PM 10 , 

### PM 2
. 5 

### to demonstrate compliance with the applicable conditions and limitations set forth in this permit and furnish KDHE a written report of the results of such performance test(s).

B. Within 60 days after achieving a maximum production rate at which the combined cycle unit (CT +HRSG) will be operated, but not later than 180 days after initial start-up of the combined cycle unit, the owner or operator shall conduct performance test for Sulfuric Acid Mist to demonstrate compliance with the estimated emission rates supplied in the permit application and furnish KDHE a written report of the results of such performance test
C. In accordance with 40 CFR Part 60, Subpart KKKK, all continuous monitoring systems and monitoring devices required shall be installed and operational prior to conducting performance tests under 40 CFR 60.8. Verification of operational status, at a minimum, includes completion of the manufacturer's written requirements or recommendations for installation, operation, and calibration of the device as required by 40 CFR 60.13.

D. In conducting the performance tests required by this permit, the reference test methods and procedures outlined in K.A.R. 28-19-212 and approved by KDHE, shall be used to demonstrate compliance with the limitation and conditions set forth in this permit

D. For the emergency diesel engine, the owner or operator must install, configure, operate, and maintain the engine and control device according to the manufacturer's emission-related written instructions. The owner or operator must not change emission-related settings in a way that is not permitted by the manufacturer, or thereafter demonstrate compliance as specified at 40 CFR 60.42ll(g)(3).

E. Compliance with NOx 

### emJssJon limits for the combined cycle unit (CT + HRSG) shall be demonstrated with a NOx 

### continuous emission monitor (CEM) that follows the requirements listed in 40 CFR 60.4340(b).

F. The N Ox 

### CEM shall be installed, certified, operated, maintained, and quality assured m accordance with 40 CFR 60.4345.
G. Compliance with S0 2 

### emission limits shall be demonstrated in accordance with the requirements in 40 CFR 60.4330 and 40 CFR 60.4360.

Page 10 of 16H. Malfunction: The Owner or Operator must notify KDHE by telephone, facsimile, or electronic mail transmission within two (2) working days following the discovery of any failure of air pollution control equipment, process equipment, or of the failure of any process to operate in a normal manner which results in an increase in emission above the allowable emission limit stated in section "V. Air Emission Limitations" of this permit, a written notification shall be submitted within ten (10) days of the event. The written notification shall include a description of the malfunctioning equipment or abnormal operation, the date of the initial malfunction, the period of time over which emissions were increased due to the failure, the cause of the failure, the estimated resultant emissions in excess of those allowed in "Air Emission Limitations," and the methods utilized to mitigate emissions and restore normal operations. Compliance with this malfunction notification shall not automatically absolve the owner or operator of liability for the excess emissions resulting from such event. The following criteria will be used by KDHE to evaluate whether emissions from a malfunction
are excluded in determining compliance with the emission rate contained herein: 1. The excess emission were caused by a sudden, unavoidable breakdown of technology, beyond the control of the owner or operator; 2. The excess emissions did not stem from any activity or event that could have been foreseen and avoided, or planned for, and could not have been avoided by better operation and maintenance practices; 3. To the maximum extent practicable, the air pollution control equipment or processes were maintained and operated in a manner consistent with good practices for minimizing em!SS!Ons; 4. Repairs were made in an expeditious fashion when the operator knew or should have known that applicable emission limitations were being exceeded. Off-shift labor and overtime must have been utilized, to the extent practicable, to ensure tbat such repairs
were made as expeditiously as practicable. 5. The amount and duration of the excess emissions (including any bypass) were minimized to the maximum extent practicable during periods of such emissions; 6. All possible steps were taken to minimize tbe impact of the excess emissions on ambient air quality; 7. All emission monitoring systems were kept in operation if at all possible; 8. The owner or operator's actions in response to the excess emissions were documented by properly signed, contemporaneous operating logs, or other relevant evidence; 9. The excess emissions were not part of a recurring pattern indicative of inadequate design, operation, or maintenance; and 10. The owner or operator properly and promptly notified the appropriate regulatory authority.

Page 11 of 16I. 

### Stack parameters for all equipment listed under Section III, Air Emissions Unit Technical Specifications, which may include, but not limited to stack heights, stack diameters, exhaust temperatures, emission rates, and exit velocities, shall be consistent with data provided for the dispersion modeling analysis. Actual operational conditions shall be consistent with data provided for the dispersion modeling analysis.



### VIII. Recordkeeping

A. 

### The owner or operator of the combined cycle unit (CT +HRSG) shall maintain records of the
occurrence and duration of any start-up, shut-down, or malfunction in the operation of the combined cycle unit (CT +HRSG); any malfunction of the air pollution control equipment; or any periods during which a continuous monitoring system or monitoring device is inoperative. These requirements are described in 40 CFR 60.7(b).

B. As required under 40 CFR 60.7 (f), the owner or operator shall maintain a file of all measurements, including continuous monitoring system, monitoring device, and performance testing measurements; all continuous monitoring system performance evaluations; all continuous monitoring system or monitoring device calibration checks; adjustments and maintenance performed on these systems or devices; and all other information required by this part recorded in a permanent form suitable for inspection. The file shall be retained for at least two years following the date of such measurements, maintenance, reports, and records, with certain exceptions specified under 40 CFR 60.7(f).
C. Reports of excess emissions shall be submitted semi-annually m accordance with the requirements in 40 CFR 60.7(c).

D. Records shall be kept on site for two (2) years in accordance with 40 CFR 60.7(f).

E. For the emergency diesel engine, the owner or operator must keep records of the emergency and non-emergency operations of the engine through a non-resettable hour meter if it does NOT meet the standards applicable to the non-emergency engines in the applicable model year. The times of operation and the reasons for operation must be recorded, as specified in 40 CFR 60.4214(b). F. A record shall be maintained demonstrating that the auxiliary boiler is in compliance with the particulate matter emission rate limit of Section V.C. Air Emission Limitations of this permit. After the initial evaluation, the particulate emission rate limitation shall be re-evaluated when either the process changes or an emission factor increases.
G. In accordance with 40 CFR 60.7(b), the owner/operator shall keep records of the occurrence and duration of any start-up, shutdown or malfunction in the operation ofthe auxiliary boiler.

H. 

### In lieu of the daily record keeping requirements of 40 CFR 60.48c(g), the owner or operator shall record and maintain records of the amount of fuel combusted in the auxiliary boiler on a monthly basis. The records of the amounts of fuel burned can be maintained in the form of monthly fuel bills or meter readings, or other records that adequately document fuel usage.

Page 12 of16I. 

### In accordance with 40 CFR 60.48c(i), all of the required records shall be maintained by the
owner or operator of the auxiliary boiler for a period of two years following the date of record.



### IX. Reporting 

### Reports demonstrating compliance shall be submitted to the KDHE in the same units as stated in the applicable requirements.

A. 

### Items required to be reported semi-annually shall be submitted to KDHE and postmarked by the 30th day following the end of each calendar half.

B. Items required to be reported annually shall be submitted to KDHE and postmarked by the 30th day following the end of each calendar year.
C. The combined cycle combustion unit (CT+HRSG) excess emissions and monitoring systems performance report and/or a summary report shall be submitted to the KDHE as required by 40 CFR 60.7(c) on a semi-annual basis. The sunnnary report form shall contain the information and be in the format as specified in 40 CFR 60.7(d). One summary report form for NOx and one summary report form for the sulfur content of the fuel shall be submitted. Written reports of
excess emissions shall include the following information:
1. The magnitude of excess emissions computed in accordance with 40 CFR 60.13(h), any conversion factor( s) used, the date and time of commencement and completion of each time period of excess emissions, and the process operating time during the reporting period.

2. Specific identification of each period of excess emissions that occurs during start-ups, shut-downs, and malfunctions, the nature and cause of any malfunction (if known), the corrective action taken or preventative measures adopted.
3. The date and time identifying each period during which the continuous monitoring system was inoperative except for zero span checks and the nature of the system repairs and adjustments.
4. When no excess emissions have occurred or the continuous monitoring system(s) have not been inoperative, repaired, or adjusted, such information shall be stated in the report.
D. Reports required under Section IX. Reporting, Item C of this permit, periods of excess emissions
as defined in 40 CFR 60.4350 shall be reported accordingly.

E. The compliance demonstration for Section V. Air Emission Limitations, Item D, of this permit, shall be reported on an annual basis.

Page 13 of 16

### F. If significant changes are made, or modeling parameters are not representative of site conditions, the owner or operator shall document compliance with the applicable NAAQS and allowable PSD increment consumption and submit documentation of compliance to KDHE prior to making the change(s). KDHE has final authority in determining what constitutes a significant change. If 

### modeling indicates a potential NAAQS or increment exceedance, then mitigation shall be required.

X. Notification


### A. The Air Quality Representative in the Southeast District Office shall be notified within 30 days of when installation of the equipment is complete so an evaluation may be conducted to verify compliance with applicable regulations.

B. K.A.R. 28-19-720 (40 CFR 60.7(a) and 60.8(d) reqmres that written notifications of the following be submitted to KDHE:

I. 

### The date construction of the combined cycle unit (CT+HRSG), the auxiliary boiler and the emergency diesel generator are commenced. The notification is to be postmarked no less than 30 days after such date.
2. The actual date of initial startup of the combined cycle unit (CT+HRSG), auxiliary boiler and emergency diesel generator. The notification is to be postmarked within 15 days after such date.

3. The actual date the combined cycle unit (CT+HRSG) enters commercial operation and the date(s) Unit 7 and Unit 8 are removed from serv1ce. The notification is to be postmarked within 15 days after such date(s).
4. The date when the initial performance testing of the combined cycle unit (CT +HRSG) is to commence. The notification is to be postmarked no less than 30 days prior to such date.
5. The date upon which demonstration of the continuous monitoring system performance
commences in accordance with 40 CFR 60.13(c). Notification shall be postmarked no less than 30 days prior to such date.
C. Notification of the performance test shall include a performance test protocol which includes a description of the test and applicable test methods. Notification of the date(s) for performance testing shall be submitted to KDHE, postmarked at least 30 days prior to such date(s). Performance testing shall also be coordinated with the KDHE Bureau of Air, Compliance and Enforcement Section at 785-296-0243 at least 30 days prior to the date(s) of the test.

Page 14 of 16

### D. At the time of permit issuance, the turbines are subject to 40 CFR Part 63, Subpart YYYY, however pursuant to 40 CFR 63.6095(d) there has been a stay of standards for gas-fired subcategories. Owners or operator of lean premix gas-fired stationary combustion turbines and diffusion flame gas- fired turbines must comply with the initial notification requirements set forth in 40 CFR 63.6145 but need not comply with any other requirement of 40 CFR Part 63 Subpart YYYY until EPA takes final action to require compliance and publishes a document in the Federal Register. [40 CFR 63.6095(d)]

XI. General Provisions



### A. This document shall become void if construction, installation or modification to convert the existing Riverton 12 simple cycle combustion turbine to a combined cycle unit has not commenced within 18 months of the effective date of this permit, or if the construction, installation or modification to convert the simple cycle combustion turbine to a combined cycle unit is interrupted for a period of 18 months or longer.

B. A construction permit or approval must be issued by KDHE prior to commencing any construction or modification of equipment or processes which result in an increase in potentialto-emit equal to or greater than the thresholds specified at K.A.R. 28-19-300.

C. Upon presentation of credentials and other documents as may be required by law, the permittee shall allow a representative of the KDHE (including authorized contractors of the KDHE) to:
I. 

### enter upon the permittee's premises where a regulated facility or activity is located or conducted or where records must be kept under conditions of this document;

2. have access to and copy, at reasonable times, any records that must be kept under conditions of this document;

3. inspect at reasonable times, any facilities, equipment (including monitoring and control equipment), practices or operations regulated or required under this document; and

4. sample or monitor, at reasonable times, for the purposes of assuring compliance with this document or as otherwise authorized by the Secretary of the KDHE, any substances or parameters at any location.

D. The emission unit or stationary source which is the subject of this document shall be operated in compliance with all applicable requirements of the Kansas Air Quality Act and the Federal Clean Air Act.

E. This document is subject to periodic review and amendment as deemed necessary to fulfill the intent and purpose of the Kansas Air Quality Statutes and Regulations and rules promulgated in accordance therewith.

Page 15 of 16

### F. This document does not relieve the permittee of the obligation to obtain other approvals, permits, licenses or documents of sanction which may be required by other federal, state or local government agencies.
G. Issuance of this document does not relieve the owner or operator of any requirement to obtain an air quality operating permit under any applicable provision ofK.A.R. 28-19-500.

Permit Engineer 

# $:::&=

Environmental Engineer Air Permits Section

LDL:lv


### c: SEDO C-10913 Date Signed

Page 16 of 16

### PSD AIR CONSTRUCTION PERMIT APPLICATION


# ADDENDUM
– GREENHOUSE GAS BACT ANALYSIS Riverton Facility Unit 12 Conversion to Combined Cycle Project

B&V PROJECT NO. 176883

PREPARED FOR



# Empire District Electric Company

MARCH 20 13

® ®©Black & VeatchHolding Company 2012. All rights reserved.Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Table of Contents i 

# Table of Content s
**Acronym List**

**................................ ................................**  **................................ ................................**  **........................... 1**  **1.0 Introduction** 

**................................ ................................**  **................................ ................................**  **.......... 1** 

**- 1**  **2.0 Greenhouse Gas**  **BACT Basis**

**................................ ................................**  **................................ ............**  **2**

**- 1**  **3.0 Combined Cycle Combustion Turbine** 

**................................ ................................**  **......................... 3** 

**- 1**  3.1 Step 1

– Identify All Control Technologies

................................ ................................ ................ 3

- 1 3.1.1 Carbon Capture and Storage

................................ ................................ ........................ 3

- 1 3.1.2 Inherently Lower Emitting Process and Practices

................................ .............. 3

- 3 3.2 Step 2

– Eliminate Technically Infeasible Options

................................ ................................ . 3

- 5 3.2.1 Carbon Capture and Storage

................................ ................................ ........................ 3

- 5 3.2.2 Inherently Lower Emitting Process and Practices

................................ .............. 3

- 6 3.3 Step 3

– Rank Remaining Control Technologies by Control Effectiveness

.................. 3

- 7 3.4 Step 4

– Evaluate Most Effective Controls

................................ ................................ ................. 3

- 7 3.4.1 Carbon Capture and Storage

................................ ................................ ........................ 3

- 8 3.4.2 Inherently Lower Emitting Process and Practices

................................ .............. 3

- 9 3.5 Step 5

– Select B ACT

................................ ................................ ................................ ........................... 3

- 9 3.5.1 Proposed CCCT BACT Emission Limit

................................ ................................ .... 3

- 10 3.5.2 Proposed Co mpliance Monitoring

................................ ................................ ........... 3

- 10 **4.0 Auxiliary Boiler** 

**................................ ................................**  **................................ ................................**  **.... 4** 
**- 1**  **5.0 Emergency Diese**  **l Generator**

**................................ ................................**  **................................ ..........**  **5**

**- 1**  **6.0 SF**  **6 Insulated Circuit Breakers** 

**................................ ................................**  **................................ ........**  **6**

**- 1**  6.1 Step 1

-- Identify All Control Technologies

................................ ................................ .................. 6

- 1 6.2 Step 2

-- Eliminate Technically Infeasible Op tions

................................ ................................ ... 6

- 1 6.3 Step 3

-- Rank Remaining Control Technologies by Control Effectiveness

.................... 6

- 1 6.4 Step 4

-- Evaluate Most Effective Controls

................................ ................................ ................... 6

- 1 6.5 Step 5

-- Select BACT

................................ ................................ ................................ ............................. 6

- 1 **7.0 Suggested Permit Conditions** 

**................................ ................................**  **................................ ..........**  **7**
**- 1** 
**Appendix A. GHG Emission Calculations** 

**................................ ................................**  **................................ A** 
**- 1** 



### LIST OF TABLES Table 3

- 1 Estimated Costs for Post

- combustion CCS

................................ ................................ ................ 3

- 9Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Acronym List AL

- 1 

# Acronym List

BACT Best Available Control Technology BHP B reak h orsepower Btu British Thermal Unit CAA Clean Air Act Amendments of 1990 CCCT C ombined cycle combustion turbine CCS Carbon capture and storage CO 2 Carbon Dioxide CO 2e Carbon Dioxide Equivalent ECBMR Enhanced Coal Bed Methane Recovery Empire District Empire District Electric Company EOR Enhanced Oil Recovery GHG Greenhouse Gas GWP Global Warming Potential HRSG H eat recovery steam generator IGCC Integrated Gasification Combined Cycle KDHE Kansas Department of Health and Environment kW Kilowatt kWh Kilowatt

- hour LDAR Leak Detection and Repair LSFO Low Sulfur Fuel Oil MEA Monoethanolamine MMBtu Million British Thermal Units MW Megawatt MWh Megawatt

- hour NSPS New Source Performance Standard PSD Prevention of Significant Deterioration RBLC RACT/BACT/LAER ClearinghouseEmpire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Introduction 1

- 1 

# 1.0 Introduction

On January 25, 2013 , Empire District Electric Company (Empire District) submitted the Riverton Unit 12 Conversion to Combined Cycle Project Prevention of Significant Deterioration (PSD) Air Permit Application to the Kansas Department of Health and Environment (KDHE). That application document indicated the conversion of Unit 12 from simple cycle to combined cycle operation would trigger PSD permitting for PM/ PM 10 / PM 2.5 and Greenhouse Gases (GHGs)

. Accordingly, these pollutants are subject to full PSD review including the requirements to address Best Avai lable Control Technology (BACT), impacts upon ambient air quality, as well as impacts upo n area growth, soils, vegetation, and visibility

. As such, Empire District is submitting this Addendum to the PSD Air Permit Application to address BACT for GHGs

. Additional addendums will address the remaining PSD elements mentioned above

. As discussed in the PSD Air Permit Application document, the Project consists of the following GHG emission sources :  Conversion of the existing Unit 12 natural gas

- fired simple cycle combustion turbine to combine cycle operation with natural gas

- fired duct burners in the Heat Recovery Steam Generator (HRSG)  New natural gas

- fired auxiliary boiler  New emergency diesel generator  Two new circuit breakers GHG emissions calculations for each of the above listed sources can be found in Appendix A

.Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Greenhouse Gas BACT Basis 2

- 1 

# 2.0 Greenhouse Gas BACT Basis The Clean Air Act Amendments of 1990 (CAA) established revised conditions for the approval of pre

- construction permit applications under the PSD program. One of these requirements is that BACT be installed to control all pollutants regulated under the Act that are emitted in significant amounts from new major sources or major modifications. BACT need not necessarily result in an emissions control device. Rather, BACT is an emission limitation made on a

case - by

- case basis accounting for several project

- sp ecific factors. However, in no case is BACT allowed to be less stringent than the emissions limits established by an applicable New Source Performance Standard (NSPS)

. EPA announced its final “PSD Tailoring” rule on May 13, 2010 which established GHG emi ssion thresholds for triggering major source PSD permitting requirements including an evaluation of BACT. The emission thresholds, 100,000 for new sources and 75,000 for increases from modifications of existing sources measured in tons per year (tpy) of c arbon dioxide equivalent (CO 2e )

– took effect in 2011. As required under the NSR/PSD regulations, the BACT analysis presented herein employed the EPA

- preferred “top

- down,” five

- step analysis process to determine the appropriate emission control technologies and /or emissions limitations for the Project :  Step 1

-- Identify All Control Technologies  Step 2

-- Eliminate Technically Infeasible Options  Step 3

-- Rank Remaini ng Control Technologies by Control Effectiveness  Step 4

-- Evaluate Most Effective Controls  Step 5

-- Select BACT The following sections present the GHG BACT analysi s conducted for the Unit 12 converted combined cycle combustion turbine (CCCT) , as well as the new auxiliary boiler, emergency diesel generator , and circuit breakers. This GHG BACT analysis utilizes information from various reference and research documents developed by or for various government entities including the USEPA, the Department of Energy’s National Energy Technology Laboratory, and the Interagency Task Force on CCS to name a few. It also r elies upon information provided in a recent (August 2012) Statement of Basis developed by USEPA Region 6 for a natural gas

- fired CCCT in Texas where Region 6 remains the permitting authority for GHGs. Information from these and other sources of data are r eferenced throughout this application as footnote entries.Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3

- 1 

# 3.0 Combined Cycle Combustion Turbine

3.1 STEP 1
– IDENTIFY ALL CONTROL TECHNOLOGIES The first step in a top

- down analysis is to identify all available control options for the emission unit in question. I dentifying all the potential available control options consists of those air pollution control technologies or techniques with a practical potential for application to the emission unit and the regulated pollutant under evaluation. The potential available control technologies and techniques may include lower emitting processes and practices, as well as post

combustion controls. Lower emitting practices can include fuel cleaning, treatment, or innovative fuel combustion techniques such as pre - combustion or oxy - combustion controls. Available CO 2 control techniques include carbon capture and storage (CCS) and inherently lower emitting process and practices via energy efficient designs. The inherently lower emitting processes and practices can be evalu ated for the proposed Project (including the combustion turbine and HRSG ) , as well as on a plant

- wide basis . While this analysis will evaluate such processes and practices for the existing combustion turbine and the new HRSG, it will not focus on plant

- wi de aspects which the US EPA states in its March 2011 guidance was intended for new facilities which have more opportunity to consider such efficiency improvements during development than does an existing generating facility which should focus only upon the emitting unit (s) being modified. 1



### 3.1.1 Carbon Capture and Storage As for CCS, the USEPA, in the same March 2011 guidance document, classifies CCS as an “add

- on pollution control technology that is “available” for facilities emitting CO 2 in large amounts, including fossil fuel

- fired power plants, and for industrial facilities with high

- purity CO 2 streams (e.g., hydrogen production, ammonia production, natural gas processing, ethanol production, ethylene oxide production, cement production , and iron and steel manufacturing).” The USEPA believes that it is a technology that warrants initial consideration and should not necessarily be eliminated in Step 1, but rather should be evaluated based on technical feasibility and costs. If CCS is to be eliminated during subsequent BACT steps, then it should be done so on record of evaluation. 2 CCS involves separating and capturing CO 2 from an emission unit’s flue gas, pressurizing the captured C O 2 and finally transporting the compressed CO 2 for injection into an available geologic storage structure. There are generally three primary technologies for CO 2 capture : pre - combustion, post

- combustion, and oxy

- combustion. This GHG BACT will serve as that record of evaluation

.

3 , 4  Pre

- combustion Capture

1 USEPA, PSD and Title V Permitting Guidance for Greenhouse Gases , EPA

- 457/B

- 11

- 001 (March 2011), 30. – T y pically used in Integrated Gasification Combined Cycle (IGCC) power plants and other industrial facilities, pre

- combustion capture

2 USEPA, 32

- 33. 3 DOE/NETL, Advanced Carbon Dioxide Capture R&D Program Accomplishments (April 2012), 2

- 5. 4 Intergovernmental Panel on Climate Change, Carbon Dioxide Capture and Storage (2005), 25.Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3

- 2 processes the primary fuel in a reactor with steam and air or oxygen to produce a mixture consisting mainly of CO and hydrogen called a synthesis gas. It then requires the CO be shifted to CO 2 before being separated from the hydrogen leaving

a pure hydrog en stream to be used as the fuel

.  Post

- combustion Capture

– P rimarily being developed for conve ntional coal

- fired power plants (but there is no reason it would not be adaptable to CCCT plants) , post

- combustion capture refers to removal of CO 2 in the flue gas just prior to discharge to the atmosphere. Several post

- combustion processes are in various stages of development including absorption , adsorption , and gas separation membrane technologies. The most widely used of these technologies (and the only one that is commercially available) is absorption which uses amine or monoethanolamine (MEA)

- based solvents 5

 to chemically separate CO 2 from other flue gases. Oxy

- combustion Capture

Once captured, CO 2 must be pressurized for injection into a pipeline or other shipping container in order to be transported for ultimate sequestration such as injection into an available geologic storage structure. The following provides a list of transportation and storage options in various stages of research or development - P rimarily being developed for pulverized coal

- fired power plan ts, oxy - combustion capture use s oxygen instead of air (upstream separation required) for combustion of the fuel to produce an exhaust stream that is mainly water and CO 2 . Additional purification of the CO 2 stream may be required to meet pipeline and storage requirements.

6  Transportation :

● Pipeline

● Shipping  Underground Geological Storage

● Oil/gas fields (either abandoned fields or for e nhanced oil recovery (EOR) in active fields )

● Saline formations

● Un minable c oal seams ( with potential for enhanced coal bed methane recovery (ECBM R ))

● Other geologic media including basalts, oil or gas

- rich shale, salt caverns, and abandoned mines (all offer small niche options for storage)  Oceanic Storage  Mineral Carbonation  Industrial Uses of CO 2

5 USEPA Region 6, Statement of Basis

– Greenhouse Gas Prevention of Significant Deterioration Preconstruction Permit for the Calpine Corporation, Deer Park Energy Center (DPEC), LLC (August 2012), 8. 6 Intergovernmental Panel on Climate Change, 215

- 220, 279, 321.Empire District Electric Com pany | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3

- 3 While there are various methods of transport and storage, any discussion providing further details of these options is rather inconsequential unless and until the remaining steps of this GHG BACT analysis prove CO 2 capture is warranted (i.e., the technology is available, cost

- effective, and has no significant energy or other environmental impacts that would otherwise preclude its use). Such factors for the capture component of CCS are further evaluated in Step 4 of the GHG BACT. The USEPA applies this same approach in its March 2011 GHG guidance document wherein the agency recognizes that it is not necessary to provide a detailed evaluation of every step of the CCS process if one part of the process warrants eliminating the control technology (e.g., if transportation of CO 2 is cost

- prohibitive there is no need to continue the analysis and provide cost information for CO 2 capture). 7



### 3.1.2 Inherently Lower Emitting Process and Practices As mentioned previously, the USEPA through various guidance documents indicates that inherently lower

- polluting processes are appropriate for consideration as available control alternatives. In doing so, however, the agency has recognized th at a Step 1 list of options need not necessarily include inherently lower polluting processes that would fundamentally redefine the nature of the source proposed by the permit applicant. 8

According to the USEPA, inherently lower emitting processes and practices include methods , techniques, and systems designed to increase energy efficiency and can be classified into two categories: 1) technologies or processes that maximize the energy efficiency of the individual emissions unit and 2) those that maximize the energy efficiency a cross the entire facility. A s discussed previously, and per USEPA guidance , energy efficiency improvements shall be limited to the modified and proposed new emissions sources and will not reach out plant

- wide as is more appropriate for the construction of new facility. Given the USEPA’s stance on not allowing inherently lower emitting processes and practices to r edefine the source and the fact that the Project consists of converting an existing simple cycle combustion turbine to combined cycle (i.e., not installing a new emissions source, but rather modifying an existing one), the inhe rently lower emitting processes and practices will be limited to those p rocess and practices that can be undertaken on the modified combustion turbine and new HRSG.

9 The Project by its shear nature is designed to increase the efficiency of Unit 12 by converting it from simple cycle to combined cycle thereby capturing waste heat and converting it to useful energy that would otherwise be lost out of the s tack. Generally speaking energy efficiency

can increase from 30 percent for simple cycle turbines to 50 percent for combined cycle operation. While the conversion will make Unit 12 much more efficient, there are other design processes and operating pract ices that can further improve and assist to maintain the unit’s energy efficiency. Based on Black & Veatch’s knowledge of power plant design and operation, as well as other GHG

7 USEPA, 42. 8 USEPA, 24. 9 USE PA, 29

- 30.Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3

- 4 permits and permit applications for similar natural gas

- fired CCCTs 10 , 11

 , the following inherently lower emitting processes and practices are presented as available GHG control technologies/energy efficiency measures: Periodic Maintenance and Tuning

 – F ollow manufacturer recommendations regarding inspection and maintenance activiti es to maintain/restore optimal efficiency

. Reduce Heat Los s es

 – I nstall insulation on both the steam turbine and HRSG components to minimize heat loss thereby increasing energy efficiency via heat recovery. In addition, the HRSG stack will have a damper a nd insulation below the damper to minimize heat loss during shutdowns thereby reducing startup times

. Instrumentation and Controls

 – E mploy the use of the latest computer

- based control systems (including upgrade of present combustion turbine control system ) to monitor and optimize fuel and air flows which optimizes combustion operations thereby producing the maximum amount of power for the least amount of fuel burned while maintaining emissions performance over a range of load and ambient temperature condi tions

. Steam Cycle Efficiency

 – E mploy a reheat steam cycle with high steam temperatures to increase the amount of power generated from the recovered waste heat. Heat Exchanger Design

 – S elect a design which optimizes waste heat transfer from the combustion turbine exhaust gas while minimizing corrosion at the outlet of the HRSG

. Minimize Fouling of Heat Exchanger Surfaces

 – E mploy inlet air filtering, proper feed water chemistry, and tube surface cleaning practices to minimize fouling of the heat exchange s urfaces and maintain the maximum waste heat exchange between the combustion turbine exhaust gas and the HRSG thereby maintaining/restoring optimal efficiency

. Reduce Steam Los s es

 – F ollow an inspection routine that checks for and repairs steam leaks from v alve, flanges, and piping to maintain/restore optimal efficiency

. Use of “Clean Fuels”

10 USEPA Region 6,, 10

- 13. – N atural gas has the lowest carbon content of any fossil fuel and will be utilized in both the combustion turbine and HRSG. While the USEPA does include the use of “c lean fuels” in the definition of BACT, and other fuels (such as hydrogen and bio

- fuels) do exist that would produce little to no net CO 2 emissions, the agency has stated that the initial list of control options for a BACT analysis does not need to include “clean fuel” options that would fundamentally redefine the source including those that would require a permit applicant to switch to a primary fuel type (i.e., coal, natural gas, or biomass) other than the type of fuel

11 NRG Texas Power LLC, Application for PSD Air Quality Permit Greenhouse Gas Emissions Unit 5, S.R. Bertron Generating Station, Laporte, Harris County, Texas (November 26, 2012), 6

- 3, 6

- 4.Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSI S

BLACK & VEATCH | Combined Cycle Combustion Turbine 3

- 5 that an applicant proposes to use for its primary combustion process. 12



### 3.2 STEP 2
– ELIMINATE TECHNICALL Y INFEASIBL E OPTIONS Unit 12 is currently designed and permitted to burn natural gas (the lowest carbon content fossil fuel available) and will continue to do so after the conversion to combined cycle.

The second step of the top

- down analysis is to identify the technical feasibility of the control options identified in Step 1, which are evaluated with respect to source

- specific factors. A control option that is determined to be technically inf easible is eliminated. “Technically infeasible” is defined as a clearly documented case of a control option that has technical difficulties that would preclude the successful use of the control option because of physical, chemical, and engineering princip les. After completion of this step, technically infeasible options are then eliminated from the BACT review process. Conversely i n Step 2, the control option may be identified as technically feasible. A “technically feasible” control option is defined as a control technology that has been installed and operated successfully at a similar type of source of comparable size under review (demonstrated). If the control o ption cannot be demonstrated, the analysis gets more involved. When determining if a control option has not been demonstrated, two key concepts need to be analyzed. The first concept, “availability,” is defined as technology that can be obtained through commercial channels or is otherwise available within the common sense meaning of the term. A technology that is being offered commercially by vendors or is in licensing and commercial demonstration is deemed an available technology. Technologies that are in development (concept stage/research and patenting) and testing stages (bench

- scale/laboratory testing/pilot scale testing) are classified as not available. The second concept, “applicability,” is defined as an available control option that can

reasona bly be installed and operated on the source type under consideration. In summary, the commercially available technology is applicable if it has been previously installed and operated at a similar type of source of comparable size, or a source with similar gas stream characteristics.



### 3.2.1 Carbon Capture and Storage While many of the CO 2 capture technologies discussed previously are at various stages of bench or pilot scale deployments, and none to

- date have been applied to full

- scale natural gas

- fired power gene ration, the USEPA has indicated that CCS should be evaluated beyond technical feasibility. As such, this analysis will continue under the assumption that post

- combustion capture using absorption technology such as amine/ MEA is technically feasible while other capture technologies including pre

- combus tion and oxy

- combustion are not

. These other technologies are infeasible because they have not to

- date been applied at the appropriate scale (e.g., post

combustion adsorption or gas separation membrane techno logies); or because they would fundamentally redefine the source (e.g., pre

- combustion and oxy

- combustion) by either requiring

12 USEPA, 27.Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3

- 6 new combustion units capable of combusting low CO 2 fuels (such as hydrogen) of which the existing unit is not capable. This is c ommensurate with other recent GHG BACT determinations made by the USEPA for similar natural gas fired generation technologies. 13 The non

- commercial availability of these technologies is further evidenced by DOE/NETL research as recent as 2011 which confirm s that commercial CO 2 capture technology for large

- scale power plants is not yet available and indicates that it may take until 2020 to become so. 14 CO 2 transportation via pipeline and shipping is considered technically feasible as these are the primary tr ansportation methodologies utilized for compressed CO 2 today for many industrial applications (pipelines more so than shipping)

. In fact, a pipeline is currently under construction in southeast Kansas which will transport CO 2 from a fertilizer plant in Coffeyville, KS to Burbank, OK for EOR 15 making it the nearest CO 2 pipeline to Riverton according to the National Energy Technology Laboratory

. 16 CO 2 storage is also considered technically feasible since such practices with respec t to EOR have been used for decades ( although of concern today is the permanent sequestration of the CO 2 once it has done the EOR)

. Other potential storage options such as gas/oil fields and saline formations are currently being evaluated across the Unit ed States including Kansas. However, these are still in the research and development stage 17



### 3.2.2 Inherently Lower Emitting Process and Practices and are not yet commercially available. All other storage options listed in Section 3.1.1 are still in the research and development phase with small scale bench a nd pilot scale deployment and as such are considered infeasible. Regardless of whether various storage options are feasible or not , including the distance a pipeline must traverse to find a suitable storage solution , CO 2 capture must still first prove eco nomical before any more detailed consideration of storage options is warranted. A discussion of such economic consideration for CO 2 capture is provided in Section 3.4.

With the exception of the use of low carbon content fuels other than natural gas, a ll of the energy efficiency improvements discussed in Section 3.1.2 are commonly utilized in CCCT facilities across the country and are thus considered feasible.

13 USEPA Region 6, 13. 14 DOE/NETL, Carbon Sequestration Program: Technology Program Plan (February 2011), 10. 15 Walton, Rod. “Chaparral Energy to pipe CO2 to help extract Osage County oil,” Tulsa World, December 26, 2012, http://www.tulsaworld.com/business/article.aspx?subjectid=49&articleid=20121226_49_A16_CUTLIN234763

. 16 NETL. “Carbon Storage.” http://www.netl.doe.gov/technologies/carbon_seq/FAQs/carboncapture3.html (Accessed March 7, 2013). 17 Graff, Trevor . "Kansas Geological Survey begins testing for CO2 underground , " The University Daily Kansan, September 12, 2012, http://kansan.com/news/2012/09/12/kansas

- geological

- survey
- begins

- testing

- for

- co2

- storage

- in

- underground

- sal ine

- reservoirs/?print=26693005342

.Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3

- 7 

### 3.3 STEP 3
– RANK REMAINING CONTR OL TECHNOLOGIES BY CONTROL EFFECTIVENESS The third step of the top

- down analysis is to rank all the remaining control alternatives not eliminated in Step 2, based on control effectiveness for the pollutant under review. If the BACT analysis proposes the top control alternat ive, there would be no need to provide cost and other detailed information in regard to other control options that would provide less control. Otherwise, the analysis should proceed to Step 4. The following list ranks the remaining control technologies not eliminated in Step 2 (list ed in order of greatest control to least control) :  Carbon Capture and Storage

– P ost

- combustion capture using absorption techniques such as amine/MEA are generally capable of 85 to 90 percent CO 2 reduction

.  Conversion to Combi ned Cycle Operation

– Inherent in the project design Unit 12 will experience an efficiency improvement by implementing waste heat recovery via installation of an HRSG for combined cycle operation. Increases in thermal efficiency from around 30 percent for simple cycle operation to 50 percent for combined cycle operation are typical; resulting in approximately 40 percent reduction in GHG emissions

.  Inherently Lower Emitting Process and Practices

– While not readily quantifiable , the measures listed in Secti on 3.1.2 will provide additional efficiency improvements to the converted CCCT.


### 3.4 STEP 4
– EVALUATE MOST EFFECT IVE CONTROLS Once the control effectiveness is established in Step 3 for all the feasible control technologies identified in Step 2, additional e valuations of each technology are performed to make a BACT determination in Step 4. The impacts of the technology implementation on the viability of the control technology at the source are evaluated. The evaluation process of these impacts is also known as an “Impact Analysis.” The following impact analyses may be performed:  En ergy evaluation of alternatives  Environme ntal evaluation of alternatives  Econ omic evaluation of alternatives The first impact analysis addresses the energy evaluation of alternatives. The energy impact of each evaluated control technology is the energy penalty or benefit resulting from the operation of the control technology at the source. Direct energy impacts include such items as the auxiliary power consumption of the control technology and the additional draft system power consumption to overcome the additional system resistance of the control technology in the flue gas flow path. The costs of these energy impacts are defined either in additional fuel costs or the cost of lost generation, which impacts the cost

- effectiveness of the control technology. The second impact analysis addresses the environmental evaluation of alternatives. Non

air quality enviro nmental impacts are evaluated to determine the cost to mitigate the environmental impacts caused by the operation of a control technology. Examples of non

- airEmpir e District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3

- 8 quality environmental impacts include polluted water discharge and solids or waste generation. The procedure for conducting this analysis should be based on a consideration of site

- specific circumstances. The third and final impact analysis addresses the economic evaluation of alternatives. This analysis is performed to indicate the cost to purch ase and o perate the control technology. Information should be obtained from established sources that can be referenced. The estimated cost of control is represented as an annualized cost ($/year) and, with the estimated quantity of pollutant removed (ton s/year), the cost

- effectiveness ($/tons) of the control technology is determined. The cost

- effectiveness describes the potential to achieve the required emissions reduction in the most economical way. The cost

- effectiveness compares the potential technol ogies on an economical basis.



### 3.4.1 Carbon Capture and Storage The addition of CCS to a power generation facility will have negative energy and environmental impacts upon the plant and its surroundings. Auxiliary power is required to operate the CO 2 capture technologies thereby decreasing the net electrical output of the plant and reducing net plant efficiency ; auxiliary power is also required for CO 2 compression

. Studies estimate that use of CCS at a power generating facility could decrease power g enerating capacity by as much as one third and net plant efficiency by 7 to 10 percent depending on the type of facility

. 18 Additionally, to meet the facility’s power output requirements, additional/larger combustion sources would need to be installed at t he plant or replacement power sourced from the grid ultimately resulting in additional GHG emissions ( as well as traditional criteria pollutants) per MW of generation. As for negative environmental impacts, the addition of amine or MEA post

- combustion CCS would require significant additional water usage and land resources 19
The biggest detractor to installation of a CCS system, however, is the cost. The majority of the cost associated with CCS is due to the post

- combustion capture and compression system. Costs for post

- combustion CO 2 capture, transport, and storage are shown in Table 3

- 1. As illustrated in Table 3

- 1, the cost of CO 2 capture is appr oximately $95 per ton of CO 2 removed (without transportation and storage which are small comparatively) which is not cost effective. In fact, this equates to an annualized cost of approximately $88 million for installation and operation of CCS. Research done by the government’s Interagency Task Force indicates that adding carbon capture to a 550 MW reference natural gas fired CCCT would increase capital cost by $340 million. , as well as amine emissions from the stack and a solid/sludge waste from the cleanup of the amine solution

.

20

18 DOE/NETL, Advanced

... , 6. Scaling this data to the appropriate size for Unit 12 would indicate an increase in capital cost of approximately $211 million which would more than double currently estimated capital cost of the Project without CO 2 capture. The research further indicat es the unit could experience as much as a

19 DOE/USEPA (Co

- task Force Leaders), Report of the Interagency Task Force Carbon Capture and Storage (August 2010), 35. 20 DOE/USEPA, 33.Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3

- 9 57 percent increase in cost of electricity ($/MWh) by adding CCS. 21

Table 3

- 1 Estimated Costs for Post

- combustion CCS Therefore, based on the evaluation of negative energy, environmental, and economic impacts assessed here, CCS shall not be considered BACT for the Project

**CCS COMPONENT COST**  **OF CONTROL**  **($/TON CO 2**  **REMOVED) 1**  **CO 2**  **REMOVED PER YEAR** 

**(TONS) 2**  **TOTAL ANNUALIZED COST**  **($)** Capture and Compression $95 919 593 $87,361,335
Transport 3 $0.91/100 km 919 ,593 at 80 km $669,464

Storage $0.51 919, 593 $468,992

Total CCS Costs $96.24 919,593 $88, 499, 791

Project Modification Cost Total Capital Cost Capit al Recovery Factor Annualized Capital Cost Cost Comparison without CCS $140,000,000 0.1099 $15,386,000
Notes: 1. Cost values are from DOE/USEPA (Co

- task Force Leaders), Report of the Interagency Task Force Carbon Capture and Storage (August 2010), 34, 37, 44. Where ranges of values were given, the lowest bound was conservatively used. Capture and compression cost data includes all costs over the generating system’s lifetime: initial investment, operations and maintenance, cost of fuel, and cost of capital. All cost data was converted from $/tonne to $/ton. 2. Project

- specific CO 2 emission information is derived from calculations presented in Appendix A for the CCCT (combustion turbine plus HRSG) assuming a 90 percent control for post

- combustion capture. 3. P ipeline length was selected based on distance (as the crow flies) from Riverton, KS to Coffeyville, KS, the site of the nearest pipeline (currently under construction) assuming the pipeline could accommodate additional CO 2 which it may not thereby requiring an even longer pipeline for this Project

.



### 3.4.2 Inherently Lower Emitting Process and Practices The remaining control technologies (heat recovery and good combustion practices including energy efficiency improvements), howev er, have no appreciable negative energy or environmental impacts and are considered cost effective for implementation. Therefore, they will not be eliminated here and will continue on to Step 5

. 

### 3.5 STEP 5
– SELECT BACT The highest ranked control technology that is not eliminated in Step 4 is proposed as the BACT for the pollutant and emission unit under review. In addition to the conversion of Unit 12 from simple cycle to a more efficient combined cycle operation (a more than 30 percent

21 Ibid.Empire District Electric Company | ADDENDUM

– GREE NHOUSE GAS BACT ANAL YSIS

BLACK & VEATCH | Combined Cycle Combustion Turbine 3

- 10 improvement in heat rate) , the following good combustion practices to promote energy efficiency are proposed as GHG B ACT :  Follow manufacturer recommendations regarding inspection and maintenance activities to maintain efficiency

.  Install insulation on both the steam turbine a nd HRSG components to minimize heat loss. In addition, the HRSG stack shall have a damper and insulation below the damper to minimize heat loss.  Employ the use of the latest computer

- based control systems (including upgrade of present combustion turbine c ontrol s ystem) to monitor and optimize fuel and air flows.  Select a steam turbine and HRSG design that maximize s efficiency while meeting Empire District ’ s needs

.  Clean heat exchanger surfaces as needed

.


### 3.5.1 Proposed CCCT BACT Emission Limit BACT for the conve rted CCCT is good combustion practices including selected energy efficiency measures which are proposed to be made enforceable with an annual ton per year BACT limit. The USEPA in its GHG guidance has recommended that because the environmental concern with GHG emissions is their cumulative impact upon the environment, emission limitations should focus on longer

- term averages (e.g., 12

- month or 365

- day rolling average) rather than short

- term averages. 22



### 3.5.2 Proposed Compliance Monitoring As such, Empire District prop oses an annual CO 2 emission limit of 1,021,770 tons per year on a 12

- month rolling average basis

. The limit is proposed as CO 2 which accounts for 99.9 percent of total CO 2e emissions.

Empire District proposes to continue its current CO 2 monitoring methodology by determining the CO 2 mass emissions using an oxygen (O 2 ) concentration monitor in accordance with 40 CFR Part 75

. Appropriate formulas and F and Fc (carbon

- based) fuel factor s found in 40 CFR Part 75 are used in combination with the oxygen monitor data (which meets the quality

assurance requirements listed in 40 CFR Part 75 ) to determine the mass - based CO 2 emissions. This method is consistent with the CO 2 reporting requirements of 40 CFR 98, Subpart D

– GHG Mandatory Reporting Rule for Electricity Generation

.

22 USEPA, 46.Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Auxiliary Boiler 4

- 1 

# 4.0 Auxiliary Boiler The 18.6 MMBtu/hr auxiliary boiler will be fired exclusively on natural gas. Given the small size of this unit, the fact that it is already proposed to burn natu ral gas (the lowest carbon

- content fossil fuel available), and the only true identified GHG control measures are CCS and good combustion practices to promote energy efficiency, there is no reason to believe that the outcome for GHG BACT for the auxiliary b oiler will have a different result than that for the combustion turbine. Specifically, CCS has been ruled out as BACT based on cost and other negative impacts , leaving only general design and operation al practices remaining to maximize and maintain energy efficiency thereby minimizing GHG s to the most practicable extent possible. Therefore, the full 5

- step top

- down BACT approach is not presented again here as Empire District proposes to sel ect the top control technologies presented below available to smal l natural gas

- fired boilers such as the one proposed herein.
Empire District proposes the following good combustion practices as BACT for the auxiliary boiler: Selection of BACT and Compliance

 Boiler Design

 – Employ an efficient boiler design that meets Em pire’s needs using efficient burners and proper insulation materials in the boiler components to minimize heat losses thereby increasing efficiency. Periodic Boiler Tune

- ups

 – Follow manufacturer recommendations regarding inspection and maintenance activities including cleaning burners and convection tubes as needed to maintain efficiency. Air and Fuel Flow Adjustments

Empire District proposes to limit the C O 2 emissions from the auxiliary boiler on an annual basis to 9,5 12 tpy (annual averaging period) with compliance demonstrated by recording fuel usage and using emission factors presented in Appendix A of this BACT analysis to determine resulting emissions. Detailed G HG emission calculations for the auxiliary boiler are provided in Attachment A. – Manually adjust flows to maximize combustion ( automated controls were assumed to not be warranted given the small size of the boiler and the fact that the magnitude of CO 2e emissions from the boiler is less than 1 percent of the CO 2e emissions from the CCCT).Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Emergency Diesel Generator 5

- 1 

# 5.0 Emergency Diesel Generator
The exact capacity of the emergency diesel generator has not yet been determined, but for permitting purposes, Empire District has assume d the capacity to be 1 , 102 break horsepower ( B HP) or 750 kW electrical output. Because of its small size, infrequent operation, and status as emergency equipment, GHG emissions from this unit will be insignificant at an estimated 59 tpy. Also, there are no pre

- combustion or post

- combustion controls for reducing GHGs f rom internal combustion engines indicating the full 5

- step BACT evaluation for the engine is not w arranted.
Empire District proposes the only GHG control available as BACT for sources such as this which is to select the most efficient engine available that meets the plant’s emergency needs

. E mpire District also propo ses to limit annual operations to no more than 100 hours per year for maintenance and readiness testing. Selection of BACT and ComplianceEmpir e District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | SF6 Insulated Circuit Breakers 6

- 1 

# 6.0 SF 6 

# Insulated Circuit Breakers The Project will require the installation of two new SF 6 - insulated circuit breakers. SF 6 , or sulfur hexafluoride, is a potent GHG with a Global Warming Potential (GWP) of 23,900. Even so, estimated emission loses of SF 6 from circuit breakers is extremely low at only 6.9 tpy of CO 2e (only 0.0006 percent of the total Project CO 2e emissions)

. 

### 6.1 STEP 1

-- IDENT IFY ALL CONTROL TECH NOLOGIES
 Use of dielectric oil or c ompressed air circuit breakers which contain no SF 6 or other GHG pollutants.  Use of modern SF 6 circuit breaker s designed to be total ly enclosed systems with density alarms that sound when 10 percent of the SF 6 has escaped

. 

### 6.2 STEP 2

-- ELIMINATE TECHNICALL Y INFEASIBLE OPTIONS Circuit breakers with insulating gases other than SF 6 are not yet commercially available 23



### 6.3 STEP 3

-- RANK REMAINING CONTR OL TECHNOLOGIES BY C ONTROL EFFECTIVENESS and certainly any use of les s effective insulation material to control just 6.9 tpy of CO 2e would not be warranted if available. As such non

- SF 6 circuit breakers will be eliminated.

The only remaining feasible cont rol is to use a modern, totally enclosed SF 6 circuit breaker s with leak detection alarm s
. 

### 6.4 STEP 4

-- EVALUATE MOST EFFECT IVE CONTROLS With only one control option there is no need for this evaluation step

. 

### 6.5 STEP 5

-- SELECT BACT Empire District proposes to use m odern, totally enclosed SF 6 circuit breakers with density ( leak detection ) alarm s having a threshold of 10 percent

.

23 Christophorous, L.G., J.K. Olthoff, and D.S. Green, Gases for Electrical Insulation and Arc Interruption: Possible Present and Future Alternatives to Pure SF6: NIST Technical Note 1425 (November 1997).Empire District Electric Company | ADDENDUM

– GREENHOUSE GAS BACT ANALYSIS

BLACK & VEATCH | Suggested Permit Conditions 7

- 1 

# 7.0 Suggested Permit Conditions
BACT Emission Limitations  BACT for the CCCT is good combustion practices and selected energy efficiency measures. The emissions of CO 2 shall not exceed 1,021,770 tpy on a 12

- month rolling average basis. 24  BACT for the auxiliary boiler is good combustion practices. The emissions of CO 2 shall not exceed 9,512 tpy on a 12

- month rolling average basis.  BACT for the emergency diesel generator shall be the selection of the most efficient engine that meets the facility’s emergency needs.  BACT for SF 6 circuit breakers shall be installatio n of modern, totally enclosed SF 6 circuit breakers with density (leak detection) alarms and a guaranteed loss rate of 0.5 percent by weight or less per year.
Monitoring Requirements  The owner or operator shall monitor CO 2 mass emissions from the CCCT usin g an oxygen (O 2 ) concentration monitor in accordance with CO 2 calculation provisions provided in 40 CFR Part 75.  The owner or operator shall monitor CO 2 mass emissions from the auxiliary boiler by recording fuel usage and using emission factors presented in air permit application to determine resulting emissions.  The owner or operator shall implement a density (leak detection) alarm system on the SF 6 circuit breakers with a threshold of 10 percent. In the event of an alarm, the owner or operator will inv estigate the event and take any necessary corrective action to address any problems.

24 The limit is proposed as CO 2 which accounts for 99.9 percent of total CO 2e emis sions.Empire District Electric Company | ADDENDUM

– GREENHOUSE GA S BACT ANALYSIS

BLACK & VEATCH | GHG Emission Calculations A

- 1 

# Appendix A. GHG Emission Calculations

### Empire Riverton Power Station Greenhouse Gas Emissions Estimate Summary of GHG Mass and CO 2 e Emissions Table A-1
Emission Source GHG Mass Emissios 1 (tpy) GHG CO 2 e 2 (tpy) CTG and Duct Burner 1,021,791.3 1,022,755.9 Auxiliary Boiler 9,512.3 9,521.5 Emergency Generator 59.3 59.5 SF 6 Insulated Circuit Breakers 0.00029 6.9 Total Estimated Emissions (tpy): 1,031,363 1,032,344

1. The GHG Mass Emissions are based on the sum of estimated emissions of GHGs

Global Warming Potential Factors for each GHG. Notes [ ]

from each emission source. 2. The GHG CO 2 e emission are based on the sum of GHG CO 2 e emissions usingEmpire Riverton Power Station Greenhouse Gas Emissions Estimate Combustion Turbine and Duct Burner Table A-2

Pollutant Emission Source Annual Heat Input 1 (MMBtu/hr) Emission Factor 2, 3 (lb/MMBtu) Hours of Operation 4

(Hrs/Yr) Mass Emissions 5 (tpy) Global Warming Potential 6 CO 2 e (tpy)

CTG 1679.2 118.86 8760 874,181.9 1 874,181.9 Duct Burner 283.5 118.86 8760 147,588.5 1 147,588.5 CTG 1679.2 0.002205 8760 16.21 21 340.5 Duct Burner 283.5 0.002205 8760 2.74 21 57.5 CTG 1679.2 0.0002205 8760 1.62 310 502.7 Duct Burner 283.5 0.0002205 8760 0.27 310 84.9 1,021,791.3

-- 1,022,755.9 CO 2

CH 4

N 2 O

1. Annual heat input for the CTG and Duct Burner is based on performance data at 100 percent load and ambient temperature Total Estimated Emissions (tpy):

N 2 O for CTG (tpy) = 1,679.2 MMBtu/hr x 0.0002205 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 1.62 6. The Global Warming Potential factors for CO 2 , CH 4 , and N 2 O are from Table A-1 of 40 CFR Part 98, Subpart A. Notes [ ]

5. The mass emissions for CO 2 , CH 4 , and N 2 O are calculated using the annual heat input, emission factor, and hours of operation as follows: CO 2 for CTG (tpy) = 1,679.2 MMBtu/hr x 118.86 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 874,181.9 CH 4 for Duct Burner (tpy) = 283.5 MMBtu/hr x 0.002205 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 2.74 2. Emission factor for CO 2 was calculated from constants for natural gas in Section 2.3 of 40 CFR Part 75, Subpart G as follows: CO 2 (lb/MMBtu) = 1040 scf/MMBtu x 1 lb-mol/385 scf x 44 lb CO 2 /lb-mol = 118.86 3. Emission factors for CH 4 and N 2 O were calculated using specified values from Table C-2 of 40 CFR Part 98, Subpart C

CH 4 (lb/MMBtu) = 0.001 kg CH 4 /MMBtu x 2.20462 lb/kg = 0.002205 N 2 O (lb/MMBtu) = 0.0001 kg N 2 O/MMBtu x 2.20462 lb/kg = 0.0002205 4. This estimate assumes the CT and Duct Burner will operate 8,760 hours per year. as follows: of 59°F firing natural gas.

### Empire Riverton Power Station Greenhouse Gas Emissions Estimate Auxiliary Boiler Table A-3

Pollutant Emission Source Annual Heat Input 1 (MMBtu/hr) Emission Factor 2, 3 (lb/MMBtu) Hours of Operation 4

(Hrs/Yr) Mass Emissions 5 (tpy) Global Warming Potential 6 CO 2 e (tpy)
CO 2 Auxiliary Boiler 18.58 116.89 8760 9,512.2 1 9,512.2 CH 4 Auxiliary Boiler 18.58 0.002205 8760 0.18 21 3.8 N 2 O Auxiliary Boiler 18.58 0.0002205 8760 0.0179 310 5.56 9,512.3

-- 9,521.5

6. The Global Warming Potential factors for CO 2 , CH 4 , and N 2 O are from Table A-1 of 40 CFR Part 98, Subpart A. CO 2 for Aux. Boiler (tpy) = 18.58 MMBtu/hr x 116.89 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 9,512.2 CH 4 for Aux. Boiler (tpy) = 18.58 MMBtu/hr x 0.002205 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 0.18 Notes [ ] 1. The Auxiliary Boiler annual heat input is based on specifications for the conceptual design. 2. Emission factor for CO 2 was calculated using default CO 2 emissions factors for natural gas fuel from Table C-1 of 40 CFR Part 98, Subpart C as follows:

N 2 O (lb/MMBtu) = 0.0001 kg N 2 O/MMBtu x 2.20462 lb/kg = 0.0002205 4. This estimate assumes the auxiliary boiler will operate 8,760 hours per year. 5. The mass emissions for CO 2 , CH 4 , and N 2 O are calculated using the annual heat input, emission factor, and hours of operation as follows: CH 4 (lb/MMBtu) = 0.001 kg CH 4 /MMBtu x 2.20462 lb/kg = 0.002205 CO 2 (lb/MMBtu) = 53.02 kg CO 2 /MMBtu x 2.20462 lb/kg = 116.89 3. Emission factors for CH 4 and N 2 O were calculated using specified values for natural gas fuel from Table C-2 of 40 CFR Part 98, Subpart C as follows: Total Estimated Emissions (tpy):

N 2 O for Aux. Boiler (tpy) = 18.58 MMBtu/hr x 0.0002205 lb/MMBtu x 8,760 hrs/yr x 1 ton/2000 lb = 0.0179Empire Riverton Power Station Greenhouse Gas Emissions Estimate Emergency Generator Table A-4

Pollutant Emission Source Annual Heat Input 1 (MMBtu/hr) Emission Factor 2, 3 (lb/MMBtu) Hours of Operation 4

(Hrs/Yr) Mass Emissions 5 (tpy) Global Warming Potential 6 CO 2 e (tpy)
CO 2 Emergency Generator 7.27 163.05 100 59.3 1 59.3 CH 4 Emergency Generator 7.27 0.006614 100 0.0024 21 0.1 N 2 O Emergency Generator 7.27 0.001323 100 0.0005 310 0.15 59.3

-- 59.5

as follows: Model QST30-G5 NRT 60 Hz Diesel Generator Set and the default high heat value for distillate fuel oil No. 2 displayed in Table C-1 of 40 CFR 98, Subpart C. The heat input is calculatedas follows:

6. The Global Warming Potential factors for CO 2 , CH 4 , and N 2 O are from Table A-1 of 40 CFR Part 98, Subpart A. CO 2 (lb/MMBtu) = 73.96 kg CO 2 /MMBtu x 2.20462 lb/kg = 163.05 3. Emission factors for CH 4 and N 2 O were calculated using specified values from Table C-2 of 40 CFR Part 98, Subpart C as follows: CH 4 (lb/MMBtu) = 0.003 kg CH 4 /MMBtu x 2.20462 lb/kg = 0.006614 N 2 O (lb/MMBtu) = 0.0006 kg N 2 O/MMBtu x 2.20462 lb/kg = 0.001323 4. This estimate assumes the auxiliary boiler will operate 100 hours per year. 5. The mass emissions for CO 2 , CH 4 , and N 2 O are calculated using the annual heat input, emission factor, and hours of operation as follows: CO 2 for Emerg. Gen. (tpy) = 7.27 MMBtu/hr x 163.05 lb/MMBtu x 100 hrs/yr x 1 ton/2000 lb = 59.3 CH 4 for Emerg. Gen. (tpy) = 7.27 MMBtu/hr x 0.006614 lb/MMBtu x 100 hrs/yr x 1 ton/2000 lb = 0.0024 N 2 0 for Emerg. Gen. (tpy) = 7.27 MMBtu/hr x 0.001323 lb/MMBtu x 100 hrs/yr x 1 ton/2000 lb = 0.0005 Heat Input (MMBtu/hr) = 52.7 gallons/hour x 0.138 MMBtu/gallon = 7.27 Notes [ ] 1. The annual heat input for the emergency generator is based on fuel consumption data at full standby for a Cummins Inc.

2. Emission factor for CO 2 was calculated using default CO 2 emissions factors from Table C-1 of 40 CFR Part 98, Subpart C Total Estimated Emissions (tpy):

### Empire Riverton Power Station Greenhouse Gas Emissions Estimate Electrical Equipment Insulated with SF 6 Table A-5

Pollutant Emission Source Count (Breakers) Mass of SF 6 per Breaker (lb/Breaker) Annual SF 6 Leak Rate (% by weight) Mass Emissions 1 (tpy) Global Warming Potential 2 CO 2 e (tpy)

SF 6 Electrical Breakers 2 58 0.5 0.00029 23,900 6.9 0.00029

-- 6.9 Total Estimated Emissions (tpy):

3. The Global Warming Potential factors for SF 6 is from Table A-1 of 40 CFR Part 98, Subpart A. Notes [ ] 1. The annual mass emissions of SF 6 from electrical breakers is calculated using the number of breakers, mass of SF 6 per breaker, and annual leak rate as follows: SF 6 for Electrical Breakers (tpy) = 2 breakers x 58 lb/breaker/year x 0.5% x 1 ton/2,000 lbs = 0.00029